Systems and methods for controlling the operation of sootblowers

ABSTRACT

Examples described herein include methods and systems for operating a sootblower for removing deposits from heat transfer surfaces of a boiler. A temperature change of a boiler fluid at one location on its flow path may be calculated during no more than substantially one stroke of the sootblower. The sootblower may then be operating using a frequency of use or a steam output selected based, at least in part, on the calculated temperature change. The temperature change of the boiler fluid during all or a portion of the sootblower stroke may be used as a relative measure of a deposition rate in the vicinity of the sootblower.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of the filing date of U.S. Provisional Application Ser. No. 61/155,037 filed Feb. 24, 2009 entitled “Soot removal based on measured rate of ash deposition” and naming Terry N. Adams as inventor, which application is hereby incorporated by reference in its entirety for any purpose.

TECHNICAL FIELD

Examples of technology described herein include boilers and sootblowers and the removal of deposits from the heat transfer surfaces of boilers.

BACKGROUND

Steam boilers may be used in many industries and electric utilities to produce steam that may be used, for example in process applications or in turbo-generators to produce electricity. Generally, steam boilers operate by flowing a fluid, such as water, inside tubes that are exposed on the outside to combustion gases. The combustion gases heat the fluid within the tubes, producing steam. Steam boilers may have a variety of configurations, and an example of a steam boiler 100 is shown in side elevation in FIG. 1. Combustion of a fuel takes place in a furnace box 105. Walls 106 and 107 define a path for combustion gases, moving in a direction indicated by arrows 110, 112, and 114.

The fluid to be heated by the steam boiler 100 is routed through tubes in the boiler. The tubes are generally arranged in sections or bundles, referred to generally as heat traps. The heat traps may for example include multiple tubes arranged in rows extending along a plane perpendicular to the page in the view shown in FIG. 1. The tubes have surfaces that serve as heat transfer surfaces, where heat from the combustion gases may be transferred to the fluid within the tube. The combustion gases generally flow countercurrent with respect to the fluid within the tubes. Multiple heat traps are shown in FIG. 1, and the different heat traps may be arranged in sections, referred to by different names according to their general position in the steam boiler 100. A first section with respect to the flow direction of the fluid inside the tubes may be referred to as an economizer 120. Liquid may enter the steam boiler 100 in the economizer section 120 and be heated to the water saturation temperature, or boiling point, for the operating pressure of the steam boiler 100. The economizer section 120 includes two heat traps 122 and 124 that are arranged in parallel. Following the economizer section 120, the fluid in the tubes enters a generating section 130. The generating section 130 in FIG. 1 includes three heat traps 132, 134, and 136. In the generating section 130, the fluid in the tubes is generally boiled to steam. An outlet from the generating section 130 may include a drum 138 that separates steam bubbles formed in the tubes from the liquid. In some steam boilers, the generating section may be the final section.

Some steam boilers are capable of generating superheated steam. Accordingly, a superheater section 140 may be provided. The superheater section 140 of FIG. 1 includes three heat traps 141, 142, and 143. In the superheater section 140, steam from the generating section 130 at or around the saturation temperature may be raised to a higher temperature, generating superheated steam.

The tubes, or tube bundles, that make up the superheater, the generating section, and the economizer may have spaces between the tubes, in part to allow for the flow of combustion gases through the bundles. When the fuel that is being fired in the furnace contains non-combustible material, called ash or soot, some of the ash may be carried by the combustion gases in the form of particles or liquid droplets into the tube bundles where it can deposit on the heat transfer surfaces. This deposition of material on the heat transfer surfaces may reduce the rate of heat transfer from the combustion gases through the tube walls to the fluid contained in the tubes, and it may also impede the flow of combustion gases passing the tube bundle. The accumulation of ash deposits on heat transfer tubes may be referred to as fouling or plugging depending on the severity of the deposits. The energy efficiency of the overall boiler may be reduced whenever heat transfer is reduced. As well, the capacity of the boiler to produce steam may be reduced if fouling and plugging hinder the flow of combustion gases. Chemical recovery boilers are one example of boilers that may be particularly prone to fouling. Coal-fired boilers and bio-mass fired boilers are two other common examples of boilers that may be prone to fouling. Generally, any boiler that is fired with an ash-containing fuel may be prone to fouling. Other types of heat exchangers that operate with one or more fluids that contain material that can foul the heat transfer surfaces and that are cleaned while in operation may experience reduced efficiency and may become plugged if cleaning is inefficient.

Fouling may in some cases be reduced by slowing the rate of carryover of ash from the furnace, or by mechanically removing the deposits from the tubes while the boiler is in operation. A common method of removing the deposits in large steam boilers is through the use of sootblowers.

Sootblowers are typically tubes that are closed at the distal end with nozzles, usually two, pointing radially outward near this end that direct high pressure steam onto the heat transfer surfaces of the steam boiler. The sootblower is connected to a source of high-pressure steam at the other end. Sootblowers may be periodically inserted through the side-walls of the boiler that enclose the tube bundles, or heat traps, and may be rotated as they are moved into and out of the heat trap along pathways designed into the bundles specifically for this purpose. High velocity steam jets may be emitted through the nozzles as the sootblowers are inserted and retracted, and the jets may impinge on and dislodge deposits from the tubes. Some points of insertion for sootblowers 150 are highlighted in FIG. 1.

A schematic illustration of a heat trap is shown in FIG. 2. A heat trap 200 is schematically illustrated as a box. Hot combustion gases 205 enter the heat trap 200, flow past heat transfer surfaces or tubes containing fluid (not shown in FIG. 2), and exit the heat trap 200 as cooler combustion gases 210. Some of the heat from the combustion gases may be absorbed in this manner by the fluid within the tubes. Six sootblowers 215-220 are shown. The sootblower 215 is partially inserted into the heat trap 200. Generally, the sootblowers 215-220 may be operated in sequence to clean heat transfer surfaces within the heat trap 200.

Steam boilers, depending on size, may have dozens of sootblowers on one or both sides of the unit depending on the anticipated severity of the ash deposit and fouling problem expected for the given fuel and steam boiler configuration. This fleet of sootblowers can use a significant portion, 10 percent or more in some cases, of the steam being generated by the steam boilers. This can be a significant loss of production capacity and can increase the cost of operation of the steam boiler. This efficiency loss may be exacerbated by the overuse of the sootblowers due to the desire of the operator of the unit to avoid a situation where the boiler becomes plugged causing unscheduled down time.

The above description of an example steam boiler and sootblowers with reference to FIGS. 1-2 is provided by way of background, and it is to be understood that steam boilers may take on a variety of configurations.

Efforts have been made to measure the degree of fouling of the various sections of an operating steam boiler. One method uses a measurement of the pressure drop, or draft loss, along the flow path of the combustion gases. Briefly, fouling may increase the resistance of the tube bundle to the flow of gases through the bundle, resulting in increased draft loss. However, this method of pressure drop measurement may not be reliable as an early warning of fouling, in part because measurable changes in draft loss only occur late in the process of fouling.

Thermodynamic methods for assessing the degree of fouling have also been proposed. An example of this type of thermodynamic method utilizes a material and energy balance for a superheater section. The steam flow from this section may be measured in steam boilers, as may be the outlet temperature of the steam. The saturation temperature of the steam entering the superheater is generally known from the operating pressure of the boiler. These two temperatures along with the well-known properties of steam can then be used in an energy balance to calculate the rate of heat transfer between the combustion gases and the steam in the superheater section. The rate of heat transfer at any time can be compared to the rate of heat transfer when the unit was clean, and when it was firing the same amount of fuel. A reduction in heat transfer between the clean condition and the fouled condition is a measure of the fouling of the superheater section. Many variations on this analysis are possible, including direct measurement of the gas temperatures into and out of the superheater section, or localized assessment of fouling by measuring the steam conditions from just one portion of the superheater.

Another method used to measure the rate of fouling uses measurements of the efficiency of the steam boiler. This method also uses common thermodynamic analysis of material and energy balances to estimate the rate of heat transfer to a section of the steam boiler or to a smaller portion of one section. These methods all typically compare the rate of heat transfer of the section to that when the section was clean. Most of the use of this method relates the decay of boiler efficiency over time to the need for sootblowing using either prescribed efficiency loss criteria or cost criteria for the sootblowing steam. Dziubakowski in U.S. Pat. No. 4,454,840 proposes the use of the overall boiler efficiency, while Klatt et al. in U.S. Pat. No. 4,466,383 and Moss et al. in U.S. Pat. No. 4,475,482 proposes the use of economic criteria for sootblowing control. Klatt et al. in U.S. Pat. No. 4,539,840 refines his method using a fit of model parameters to the overall boiler efficiency versus time.

Another approach is to calculate the rate of heat transfer before and after the full set of generating section sootblowers has been operated through one cycle. This maximizes the difference in cleanliness of the section before and after sootblowing. However this approach takes long enough, on the order of half an hour, that the combustion conditions may not be the same. The variation in combustion conditions can be larger than the expected difference in heat transfer rate for the before and after cleanliness state, and certainly different than the “clean” reference state just after startup.

Another method of assessing the cleanliness of the heat transfer surfaces in a steam boiler is to measure the weight of a section or a portion of a section. Examples of such a method may be found in U.S. Pat. No. 6,323,442, and U.S. Published Application Number 2004/0226758 and U.S. Pat. No. 7,341,067, all of which are incorporated herein by reference. Generally, the deposits on the surfaces of the tubes in a section may increase their weight. By measuring the weight when the section is clean and later during operation, the degree of fouling can be assessed, as can the effectiveness of sootblowing. This method may be advantageous in the superheater section where the individual elements that make up this section are supported from above. Strain gauges can be mounted on the support members to measure the weight.

Other methods for assessing the cleanliness of the heat transfer surfaces have been proposed. The use of a sensor on the tube surface was proposed by Perrone in U.S. Pat. No. 6,325,025. Lefebvre et al. in U.S. Pat. No. 6,736,089 proposed the use of neural networks, genetically programmed models as well as thermodynamic models to assess cleanliness. Jameel et al. in U.S. Published Application No. 2004/0006841 additionally proposed the use of cameras to assess cleanliness. All of the above mentioned patents and patent publications are hereby incorporated by reference in their entirety for any purpose.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of a boiler.

FIG. 2 is a schematic illustration of a heat trap.

FIG. 3 is a flowchart illustrating a method according to an embodiment of the present invention.

FIG. 4 is an example graph of a combustion gas temperature measurement over time according to an embodiment of the present invention.

FIG. 5 is an example graph of a combustion gas temperature measurement over time according to an embodiment of the present invention.

FIG. 6 is a schematic illustration of a system according to an embodiment of the present invention.

FIG. 7 shows example graphs of sootblower operational frequencies that may be modified according to embodiments of the present invention.

DETAILED DESCRIPTION

Certain details are set forth below to provide a sufficient understanding of embodiments of the invention. However, it will be clear to one skilled in the art that embodiments of the invention may be practiced without various of these particular details. In some instances, well-known boiler components, sootblower features, circuits, control signals, timing protocols, computing components, and software operations have not been shown in detail in order to avoid unnecessarily obscuring the described embodiments of the invention.

The above-described methods for assessing the cleanliness of heat transfer surfaces may have a variety of limitations. Thermodynamic methods described above for assessing fouling in the superheater may be limited in accuracy as a result of the fluctuations in steam conditions both in pressure and flow due to the variability of the use of the steam by equipment downstream from the steam boiler.

The thermodynamic methods described above may also be less useful for the generating section of steam boilers, which may be the location of the most serious fouling and plugging. In the steam generating section the temperature of the water/steam mixture inside the tubes is generally constant during boiling so the energy of the mixture depends on the relative proportions of steam and water, which is very difficult to measure. The flow of water in the generating section may accordingly be difficult to measure because it may be two-phase flow. As a result it may be difficult to assess fouling based on heat transfer to the waterside.

The material and energy balance approach described above may be used on the generating section if gas-side temperatures and flows are measured both into and out of the generating section. The change in energy of the combustion gases through the steam generating section can then be used to measure heat transfer. This method may be limited by the difficulty in measuring the incoming gas temperature to the generating section due to its high temperature and fouling characteristics. Temperature probes are difficult to maintain in the location at the entrance to the generating section, and they can drift in calibration due to fouling. This may reduce the accuracy of the combustion gas energy balance through the generating section.

Indeed, many locations along the gas flow path through the heat traps may be unsuitable for gas temperature measurement. As a result, an energy balance that requires both the inlet and the outlet temperature often is inaccurate or impossible due to fouling of the inlet gas temperature probe. Eliminating the need to measure the inlet conditions would solve this problem, but would generally require the assumption that the inlet conditions remain constant for the period of time that data on the change in outlet gas temperature is taken. This is essentially the assumption made by boiler efficiency methods for estimating sootblowing effectiveness. The longer the measurement duration, the poorer this assumption becomes. Embodiments of the present invention, described further below, make measurements on the order of the time it takes one sootblower to be inserted and retracted, approximately 1 to 4 minutes in some cases.

The weight measuring approach described above may also have limited application to the steam generating section. For many boilers the generating section is not supported in a way that weight can be readily measured. The generating section in these units may contain individual tubes connected at the top and bottom to large drums. This construction generally prevents the measurement of the weight of the section, and therefore the assessment of the degree of fouling in this section by the use of weight.

The limitations of existing methods described above, including difficulty in measuring temperature at the needed location, variation in combustion conditions during lengthy measurement, and the difficulty in mounting weight sensors for many boilers demonstrate some of the difficulties of assessing the effectiveness of sootblowing. Further, fouling and plugging may not be uniformly distributed throughout the various sections of a steam boiler. Accordingly, measurements effective only for a particular section may not be the most effective in maintaining the boiler.

Embodiments of the present invention for assessing the effectiveness of sootblowers will now be described. While embodiments of the present invention may overcome some of the difficulties described above, it is to be understood that not all embodiments may address all the difficulties, and some embodiments may not address any of the difficulties described above.

FIG. 3 is a flowchart illustrating a method 300 according to an embodiment of the present invention. In block 305, the temperature of a boiler fluid at one location may be measured during different times of a particular sootblower stroke. In block 310, a temperature change may be calculated between a starting time and an ending time that may be substantially one stroke or less of the particular sootblower. As will be described further below, the temperature change of the boiler fluid occurring during a stroke or less of a particular sootblower may be considered a measure of the effectiveness of the sootblower in contributing to the reduction of fouling in the boiler. As will also be described further, because sootblowers are generally effective in the removal of deposits, the change in boiler fluid temperature occurring during a stroke or less of a particular sootblower may be considered a measure of the amount of fouling, or deposits, occurring in the vicinity of the particular sootblower. Referring again to FIG. 3, various statistical manipulations may be performed with the temperature data. For example, in block 315, the calculated temperature change may be normalized for boiler conditions. In block 320, temperature changes calculated for the particular sootblower during multiple sootblowing sequences may be averaged. Some or all of blocks 305-320 may be repeated for multiple sootblowers in a steam boiler system. In block 325, a sootblowing sequence may be optimized using the temperature changes measured for the multiple sootblowers. In block 330, at least one sootblower of the system is operated with a frequency or steam output that is selected based, at least in part, on the temperature change calculated during all or a portion of a stroke of the sootblower.

In block 305, the temperature of a boiler fluid at one location is measured during different times of a particular sootblower stroke. The boiler fluid measured may be the fluid inside the tubes or may be the combustion gases. Generally, for an effective sootblower, the temperature of fluid inside the tubes may be expected to increase following the sootblower stroke, due to improved heat transfer between the combustion gases and the tubes. Likewise, the temperature of combustion gases may be expected to decrease following an effective sootblower stroke, due to improved heat transfer between the combustion gases and the tubes.

In block 305, the temperature of a boiler fluid at one location is measured during different times of a particular sootblower stroke. A sootblower stroke generally refers to the path of the sootblower from a resting position outside the heat trap, into the heat trap, and returned to the resting position. Generally, the boiler fluid may be measured when the sootblower is in a resting position prior to insertion into the heat trap, and again when the sootblower has returned to the resting position following a stroke. A sootblower stroke generally takes on the order of minutes, one to four minutes in some embodiments. Accordingly, as was described above, a temperature measurement taken at a outlet of the section during one stroke or less of a sootblower may generally be considered to occur during a period of relatively constant inlet gas temperature. In other embodiments, other measurement times may be used, such as taking a measurement at a time after the beginning of a stroke, and another time closer to the end of the stroke or after the stroke. A continuous temperature measurement may be taken in block 305, and measurements selected from different times in the sootblower stroke may be used to perform the calculation in block 310. In other embodiments, a temperature reading may only be taken at particular times.

Some embodiments may differentiate parts of the sootblower stroke. A full cycle of a sootblower involves insertion on a forward portion of the stroke, followed by extraction on a reverse portion of the stroke. The forward portion may be more effective than the reverse portion simply because the forward stroke may remove most of the deposit leaving little for the reverse stroke. In this case the temperature change may be greater for the forward portion than the reverse portion. This can be used to reduce or stop the flow of steam to the sootblower on the reverse portion of the stroke so that either another sootblower can be started or the total sootblowing steam can be reduced.

As will be described further below, the temperature measurements in block 305 may be taken from any of a variety of locations in a steam boiler. Suitable locations include an output of a generating section, a superheater section, or an economizer section of a boiler. Suitable locations also include locations between any individual heat traps within a section. Referring back to FIG. 1, one possible location for the temperature measurement is an output of the generating section 130, that is between the generating section 130 and the economizer section 120. Another possible location is between the heat traps 132 and 134, or between the heat traps 134 and 136. In embodiments of the present invention, temperature measurements taken at a single location may be used to estimate an effectiveness for any or all of the sootblowers upstream of the measurement location.

An example of a temperature measurement according to an embodiment of the present invention is shown in FIG. 4. Combustion gas temperature of gas exiting a heat trap of a steam boiler is shown versus time. Sootblower sequences begin at times 405, 410, 415, and 420 in FIG. 4. Sootblower sequences refer to the operation of multiple, or all, sootblowers in the steam boiler or section of the steam boiler. Each sootblower may operate sequentially, or in groups, during the sootblower sequence. The fluctuations of temperature shown in FIG. 4 may reflect the heat transfer response of heat traps due to changes in fouling condition as a result of the operation of the sootblowers. Sootblowers upstream of the temperature measurement may clean the heat transfer surfaces and improve heat transfer, thus lowering the measured gas temperature. Sootblowers downstream of the temperature measurement may operate when the upstream sootblowers are idle, so the heat traps upstream may foul and gas temperature may increases. The cyclic nature of the plot in FIG. 4 may generally be due to the cleaning/fouling cycle that follows the operation of the fleet of sootblowers upstream and downstream of the measurement location.

An individual sootblower stroke begins at time 425 and ends at 430. The same sootblower has another stroke beginning at time 435 and ending at time 440, another beginning at time 445 and ending at 450, and another beginning at time 455 and ending at time 460. It can be seen in FIG. 4 that the combustion gas temperature decreases during each of the sootblower strokes. By associating individual, or groups of sootblowers with different time periods in FIG. 4, an estimate of the effectiveness of the sootblowers in reducing fouling may be determined. Generally, sootblowers causing a decrease in the gas combustion temperature may be more effective than those causing a less significant decrease, or those operating during a period when the combustion gas temperature actually increases.

A measurement period between the different times of a sootblower stroke may be short relative to changes in the combustion conditions. For example, the measurement time for each individual sootblower may be on the order of a few minutes in some embodiments, as shown in FIG. 4, such as a time period between the time 425 and 430. During this time the fluctuation in boiler operating conditions, such as firing rate and combustion air flow rate, may be relatively small. As a result, the inlet gas temperature to the heat traps may be considered steady, and the outlet temperature alone may be sufficient to measure the change in fouling during the stroke of one sootblower. This may eliminate or reduce a need to make a measurement of an incoming gas temperature as was required by thermodynamic approaches described above. The temperature of the gas entering the superheater or generating sections may be difficult to measure, and is not required in embodiments of the present invention. Instead, a temperature measurement at only the output of the generating or superheater section, for example, may be used to estimate an effectiveness of any or all upstream sootblowers.

Temperature measurements taken at a location downstream of several heat traps may be used to assess the performance of multiple, or all sootblowers upstream of the measurement location. Each sootblower upstream of a measurement location may have an effect on the measured combustion gas temperature at that location. Accordingly, as will be described further below, a convenient downstream location may be selected for the temperature measurements and temperature changes calculated for each of a plurality of upstream sootblowers. Embodiments of the present invention may allow temperature measurements downstream in locations that may be easier to obtain and may yield more accurate results, than the locations required by thermodynamic approaches described above.

Referring back to FIG. 3, various statistical techniques may be used on the temperature data. In block 315, the calculated temperature change may be normalized according to boiler conditions. The normalization may account for expected changes in measured temperature for different operating conditions. The average temperature at the outlet of the generating bank, for example, may vary with the firing rate of the boiler. At low firing rates the temperature may be lower, and higher at higher firing rates. The expected change in temperature with the same degree of fouling reduction may accordingly be lower at lower firing rates and higher at higher firing rates. Normalizing the measured change in temperature for the one sootblowing cycle with the average temperature or any other normalizing parameter such as firing rate or fuel and air input rate may account for the differences. For example, normalization may allow for a more accurate comparison of the temperature changes from two different sootblowers even if the firing rate changed significantly between the times the first sootblower was stroked and when the second sootblower was stroked.

In block 320, multiple calculated temperature changes for a particular sootblower may be averaged. That is, blocks 305-315 may be repeated for multiple strokes of a particular sootblower over time. In some embodiments, a temperature change may be calculated for a particular sootblower over multiple sootblowing sequences. Multiple temperature changes for a particular sootblower may then be averaged. In some embodiments the temperature change over a single sootblower stroke may be small, on the order of a few percent of the average gas temperature, two percent in some embodiments. Accordingly, statistical averaging of a temperature change over several sootblower sequences may be used to develop a more robust indicator of the sootblower's effectiveness. Some measurements may be discarded if taken during known anomalous sootblowing sequences. In some embodiments, measurements taken during anomalous sootblowing sequences may be used but may have less deleterious effects due to their lower statistical significance. Generally, many data points may be available since each sootblower, or groups of sootblowers, may yield a measurement following each stroke. Any available statistical techniques may be used to analyze these data points and develop an overall estimate of effectiveness for the sootblower.

Other statistical techniques may also be used to manipulate temperature data collected in embodiments of the present invention. In particular, each insertion of a particular sootblower may be considered a “bump” test. This is a common statistical procedure where one operating variable is changed and the corresponding change in the output parameters is measured. This can be done once or multiple times. The output parameters may be affected by other uncontrolled fluctuations in the other input parameters such as uncontrolled fluctuations in the fuel quality of a boiler. With a single “bump” test the bump should be relatively large relative to the fluctuations to ensure that the change in an outlet parameter is primarily, or at least discernibly, affected by this controlled bump and not by the uncontrolled fluctuations. When multiple bumps are used, particularly at a known frequency, then the bumps may be smaller because statistical methods and time series methods can be used to eliminate the effect of uncontrolled fluctuations. Simple averaging of the output signals from each bump test is one way of doing this. The timing and frequency of insertions for each sootblower is well known, so fluctuations and noise due to other factors can be removed by correlation techniques. This means that the relatively small bumps due to the insertion of one sootblower may accurately indicate the true response of the gas outlet temperature due to the reduction in fouling in the vicinity of the sootblower.

Referring back to FIG. 3, any or all of the blocks 305-320 may be performed for multiple sootblowers in a boiler system. There may be generally any number of sootblowers in a system, including between 10 and 100 sootblowers in some embodiments. An indication of the effectiveness of each sootblower in reducing deposits in the system may be developed. At block 325, measurements pertaining to multiple sootblowers may be compared to optimize a sootblowing sequence based on the calculated temperature changes for each of the multiple sootblowers. Those that are considered to be more effective, for example, may be used more frequently or provided with more steam output, while those that are less effective as indicated by the temperature measurement, may be used less frequently or provided with less steam output. The sootblowing sequence may be optimized according to a desired total steam output, sootblowing frequency, or both.

Note that the effectiveness of the sootblowers generally may be quite high. Overall fouling may be a gradual process, as indicated in FIG. 5. FIG. 5 is a graph of combustion gas temperature over time, showing a gradual upward trend over weeks as the system fouls. Sootblowing sequences may take only a few hours, such as between the times 405 and 410 in FIG. 4, yet the temperature variation during the course of a sootblowing sequence may be on the same order of magnitude as the increase in average temperature over the course of several months. This generally indicates that the sootblowers are, on average, very effective at removing all but a small fraction of the material being deposited on the tubes, otherwise the heat traps would foul to the point of plugging in a matter of hours. The observed long-term rate of fouling in FIG. 5 is generally due to the fraction that is not removed during sootblowing sequences.

Accordingly, the change in temperature indicated by the difference between the measurements at different points in a sootblower stroke, such as the difference between the temperatures at times 425 and 430, may be considered a direct measure of the fouling rate in the vicinity of that sootblower. Because the sootblowers are generally effective, the amount of fouling during the time the sootblower was not operating may be estimated by the decrease in fouling after one operation of the sootblower. Generally, the temperature difference measured before and after the sootblower stroke may be considered an indication of not just the sootblower effectiveness, but the amount of fouling occurring in the vicinity of the sootblower. Accordingly, referring back to FIG. 3, the temperature change calculated in block 310 may be viewed as an estimate of the amount of fouling occurring in the boiler in the vicinity of the particular sootblower.

Continuing to refer to FIG. 3, at block 315 the frequency or steam output delivered by particular sootblowers may be adjusted in accordance with their respective temperature measurements. By reviewing the temperature differences caused by individual sootblowers, or groups of sootblowers, a boiler operator may develop an understanding of locations in the boiler where the most fouling is occurring. This information may be used to establish the frequency of operation, or steam output delivered to particular sootblowers for reducing fouling and improving boiler efficiency. The information may also be used to adjust boiler conditions or configurations to reduce fouling at particular locations. For example, the information may be used to improve the design of the boiler itself to reduce fouling, or to identify locations within the boiler for additional or reduced fouling abatement mechanisms.

Some embodiments of the present invention may also, or alternatively, provide a measurement of carryover or an estimate of an overall fouling rate in a boiler system ahead of the temperature probe. In particular, temperature changes during time periods when downstream sootblowers are operating may be used to estimate carryover. When downstream sootblowers are operating, the upstream sootblowers are generally not operating. Accordingly, temperature changes occurring during the operation of downstream sootblowers may be used as an estimate of overall fouling at the locations upstream of the temperature probe, since the temperature increase may represent fouling in the vicinity of all upstream sootblowers. For example, referring back to FIG. 4, from time 470 to time 475, sootblowers downstream of the temperature sensor may be operating, and the measured temperature is increasing. The temperature difference between the times 470 and 475 may be used as an estimate of carryover or the rate of fouling of locations upstream of the temperature probe in the system. As with measurements for individual sootblowers that are upstream of the temperature probe, the temperature difference between the times 470 and 475 may be averaged with similar temperature measurements in other sootblowing cycles to refine the carryover estimate.

Although a continuous period of time is shown in FIG. 4 during which downstream sootblowers are operating and upstream sootblowers are not, in other embodiments, there may be discontinuous periods of time within a sootblower sequence or between sequences when the upstream sootblowers are not active, and temperature changes during the discontinuous times may be combined, such as by averaging, to estimate carryover in the system.

The carryover estimate may be utilized in a variety of ways. The carryover estimate itself may be used to adjust a frequency of operation, a steam output, or both, of sootblowers. The carryover estimate may also be used to interpret measurements taken during the operation of certain upstream sootblowers, described above with reference to FIG. 3. For example, it may be determined in one example that a temperature increase of 10 degrees occurs over the time period of a sootblower stroke when no upstream sootblowers are blowing due to carryover and fouling of all upstream locations. A temperature difference of −5 degrees may be calculated during one complete stroke of an upstream sootblower. Based on the carryover or fouling measurement, it may be determined that the effective measurement of that upstream sootblower was −15 degrees, since the temperature may have been anticipated to rise 10 degrees if no sootblower was utilized, but instead the temperature declined 5 degrees over the course of the sootblower stroke. Accordingly, temperature changes calculated during all or a portion of a sootblower stroke may be added to a temperature change predicted by a carryover estimate.

The above description of embodiments of methods according to the present invention has described measurement of combustion gas temperature. It is to be understood, however, that the measurement of other boiler fluids may also be used, such as the fluid within the heat transfer tubes. The temperature of the fluid within the heat transfer tubes would generally change in an opposite direction to that of the combustion gases. Similarly, the location of ‘upstream’ and ‘downstream’ sootblowers would be different for the measurement of temperature within the heat transfer tubes, since the fluid within the tubes is generally moving in an opposite direction to the combustion gases. For example, the steam temperature at an outlet of a superheater section may be used. This temperature may also vary in a cyclic manner with the sootblowing in the superheater section. There are small step changes in steam temperature for each sootblower in this section, so their individual effectiveness and the localized rate of deposition can be used to optimize the use of the sootblowers in the superheater section. In other embodiments, the steam temperature at an outlet of an economizer section may be used.

In some embodiments, multiple temperature readings at one gas flow path location may be taken from different geometrical positions. For example, the generating section outlet may be a physically large area. There may be side-to-side or top-to-bottom variations in gas temperature at the generating section outlet. Without being bound by theory, the variations may be due in part to combustion gas channeling in the furnace, variable deposition rates, or variable effectiveness of individual sootblowers. Accordingly, temperature measurements may be taken at both a top and a bottom location of the generating section outlet or at different sides of the generating section outlet. Averaging of the temperature measurements may be used, or the temperature measurement taken closest to a particular sootblower may be used exclusively or weighted more heavily in calculating an overall estimate of effectiveness for that sootblower.

Multiple temperature measurements may also be advantageous when more than one sootblower is operated at a time. The impact on the temperature reading would be expected along the gas flow path following the location of the sootblower. For example, a sootblower in an upper, left side location may be expected to have the most impact on the gas temperature exiting the upper, left side of the boiler section. This impact would reasonable stay in the same geometrical location even as the gas flow path bends through the following heat traps. The result would be that two sootblowers could be operated simultaneously on the left and right with their impact separately recorded with temperature measurements on the left and right side. The same would be true for simultaneous sootblowers at the top and bottom.

Having described methods for estimating an effectiveness of sootblower efficiency, systems according to embodiments of the present invention will now be described. FIG. 6 is a schematic illustration of a steam boiler system 600 according to an embodiment of the present invention. A steam boiler 605 includes a furnace 607 and three heat traps 610, 615, and 620. Although three heat traps are shown, any number may be provided. One or more sootblowers 612 are provided to clean the heat transfer surfaces of the heat trap 610. One or more sootblowers 617 are provided to clean the heat transfer surfaces of the heat trap 615. Additional sootblowers, although not shown, may be provided to clean the heat transfer surfaces of the third heat trap 620. Temperature changes calculated during one stroke or less from multiple sootblowers may be used to optimize or otherwise improve overall boiler performance. That is, the use of multiple sootblowers may be adjusted to improve the boiler performance.

As was generally described above, the sootblowers 612 and 617 generally may be tubes having nozzles to direct high pressure steam onto the heat transfer surfaces of the heat trap. Any suitable sootblowers may be used in embodiments of the present invention, including sootblowers of substantially any cross-section employing any mechanism to reduce fouling at the heat transfer surfaces in the vicinity of the sootblower within the heat trap. Also, the heat traps 610, 615, and 620, each may include tubes of substantially any cross-section and configuration to route fluid through the steam boiler. Generally, the tubes containing fluids to be heated by the steam boiler are made of metal for good heat transfer between the fluid within the tubes and the combustion gas outside, however, any material may be used.

A temperature sensor 625 is provided to measure the temperature of one or more boiler fluids, as described above. The temperature sensor in FIG. 6 is positioned following the second heat trap 615. Accordingly, temperature measurements of combustion gases obtained by the temperature sensor 625 may be used to develop an estimate of effectiveness of upstream sootblowers 612 and 617, as described above. The temperature sensor may be positioned in any of a variety of locations within the boiler 605. In some embodiments, the temperature sensor 625 is placed at an outlet of a generating section of the steam boiler 605. In this manner, measurements of combustion gases taken by the temperature sensor 625 may be used to develop an estimate of effectiveness for sootblowers in the upstream generating and superheater sections. Other locations may also be used for the temperature sensor 625. In other embodiments, the temperature sensor 625 is placed downstream of the generating section. Generally, at or downstream of the generating section, the temperature measurement may itself be less subject to fouling and may be performed at a lower temperature, making the measurement more suitable for common industrial measuring instruments. Nonetheless, embodiments of the present invention may also utilize temperature measurements upstream of the generating section.

In some embodiments, the temperature sensor is located between the generating section and the economizer. This may be a common and readily accessible location for gas temperature measurement. The gas temperature at this location is typically near 300 to 400° C., and the vast majority of the carryover material that could potentially foul the temperature probe has been deposited on the heat transfer surfaces of the superheater and generating bank. The deposition and fouling rate in this area is relatively low, so the temperature probe would require little cleaning and maintenance. As well, the probe may be located near an adjacent sootblower so the cleaning of any deposits on the temperature probe would be the same as for the heat transfer surfaces themselves.

Using the outlet gas temperature from the generating section may also be advantageous because it may frequently be the superheater and generating bank that become fouled by carryover. The heat traps that follow this location in the gas flow path, such as the economizer, typically may not foul as much. The economizer usually is also cleaned by sootblowing, but not as frequently as the heat traps upstream. Locating the probe just downstream of the generating section therefore may have two advantages over other locations: 1) it automatically may provide data at times when the upstream sootblowers are all retracted, which may facilitate a measure of carryover, and 2) it may provide a maximum temperature change signal. Although locating the temperature sensor at an output of the generating section may be advantageous, other locations may also be used.

A controller 630 is coupled to the sootblowers 612 and 617. The controller 630 provides control signals to the sootblowers 612 and 617 to start and stop sootblower strokes. Accordingly, the controller 630 may control the frequency of use of each of the sootblowers in the groups 612 and 617. Although a single controller 630 is shown, multiple controller units may be provided.

A data analyzer 640 receives data from the temperature sensor 625. The data analyzer 640 may be co-located with the boiler 605, or may be in a remote location. The data analyzer 640 generally includes a processing unit 645 and a memory 650. Although a single processing unit 645 and memory 650 are shown, multiple processing units, memory devices, or both may be used. The data analyzer 640 may be implemented as a computer programmed to carry out the tasks described. The data analyzer 640 may be implemented using hardware, software, or combinations thereof. The memory 650 may be encoded with computer readable instructions that cause the processing unit 645 to perform the data analysis described herein. In some embodiments, the controller and the data analyzer 640 may be combined in a single unit. It is to be understood that the location and configuration of the data analyzer 640 are flexible in accordance with general computing technology.

The controller 630 may provide signals to the data analyzer 640 indicating when individual sootblowers, or groups of sootblowers, are at particular locations of their stroke. For example, the controller 630 may provide a signal to the data analyzer 640 when a particular sootblower begins a stroke, and when the particular sootblower ends its stroke. The controller 630 may also provide an indication of the forward and reverse portions of the stroke. The data analyzer 640 may utilize the signals indicative of the start and end of a particular sootblower stroke to identify temperature measurements from the temperature sensor 625 occurring at or near the start and end of the sootblower stroke. The data analyzer 640 may then implement statistical techniques, such as but not limited to averaging and normalizing, described above to manipulate the temperature data associated with individual sootblowers or groups of sootblowers. The temperature data may be used to select a suitable frequency for operation of the sootblowers, or a steam output of the sootblowers.

The data analyzer 640 may generate and provide signals to the controller 630 to cause the controller 630 to operate the sootblowers 612 or 617 or both, at a rate selected using the temperature changes calculated by the data analyzer 640. So, for example, the data analyzer 640 may provide a signal to the controller 630 to cause the controller 630 to increase the frequency with which one or more of the sootblowers are utilized. Sootblowers which are identified by their temperature measurements to be more effective, or to be located in areas of greater fouling, may be utilized more frequently. Similarly, the data analyzer 640 may couple a signal to the controller 630 to decrease a frequency of use of sootblowers which are identified by their temperature changes to be less effective, or to be located in areas of lesser fouling. Instead of or in addition to selecting a frequency of use of the sootblowers, the data analyzer may couple signals to the controller 630 indicative of an amount of steam to utilize for particular sootblowers.

The data analyzer 640 may also be coupled to one or more input devices 655, output devices 660, or both. The input and output devices may be used, for example, to configure the data analyzer 640 or display interim or final results generated by the data analyzer 640. In some embodiments, an output device 660 may include a display that may be located in the operating control area of the boiler 605. Both the distribution of fouling rate throughout the heat traps as well as a continuous readout of the fouling rate may be displayed based on the temperature readings associated with each sootblower. The display may assist the operating staff in optimizing firing condition to achieve lower carryover of ash.

FIG. 7 shows three bar graphs illustrating an example of frequencies of operation of sootblowers that may be selected or changed using the measured temperature changes. The graphs in FIG. 7 are based on data for a steam boiler that is similar to that of FIG. 1, although only five heat traps are shown in FIG. 7, and represent heat traps in the superheater and generating sections of a boiler. Each of the five heat traps has three sootblowers, one at the top, one at the middle, and one at the bottom of the heat trap. The bar graphs 710, 720, and 730 illustrate a frequency of sootblower operation measured in a number of strokes per day for each of the sootblowers in each heat trap.

The first bar graph of FIG. 7, graph 710, is an example of a pattern of sootblowing frequency for the individual sootblowers based on an assumed fouling distribution. The pattern of sootblowing frequency shown in graph 710 may cause the boiler to plug in a matter of several weeks. The second bar graph, graph 720, in FIG. 7 is another prescribed pattern for sootblower operation that may somewhat extend the operation of the boiler before plugging, but may also be based on an assumed fouling pattern.

The third bar graph, graph 730, illustrates a recommended number of strokes per day for each sootblower based on the temperature change measurements described above. The bar graph 730 may also be considered to illustrate an average fouling rate in the vicinity of the individual sootblowers for this boiler. This is the type of output that may be generated by the data analyzer 640 and displayed on an output device 660 of FIG. 6. The change in gas temperature upstream of a probe location during the course of the operation of each individual sootblower is compared in order to determine the relative fouling rate in the vicinity of the individual sootblowers. The sootblower with the largest change in temperature generally may indicate that the highest fouling is in the vicinity of that particular sootblower. The changes in gas temperature for the other sootblowers may be compared to this, and their relative magnitude is used to specify the relative frequency of operation of the individual sootblowers. The individual sootblowers with higher temperature change can then be operated more often than those with lower temperature change. Viewing the graph 730 of FIG. 7, the greatest fouling may be occurring in the vicinity of the sootblower at the top of the second heat trap, accordingly, it may be operated with greater frequency.

Embodiments of the present invention may advantageously improve efficiency of boilers with heat transfer surfaces prone to fouling. By selecting frequencies or steam usage for individual sootblowers or groups of sootblowers based on their measured performance, the amount of steam utilized by the sootblowers overall may be reduced, the effectiveness of the sootblowers improved, or both. These techniques may improve the overall efficiency of the boiler, which may allow the boiler to utilize less fuel for a same steam output, or to operate longer without a scheduled or unscheduled shut down due to plugging.

From the foregoing it will be appreciated that, although specific embodiments of the invention have been described herein for purposes of illustration, various modifications may be made without deviating from the spirit and scope of the invention. For example, different temperature sensor measurements and locations may be used. 

1. A method for operating a sootblower for removing deposits from heat transfer surfaces of a boiler, the method comprising: calculating a temperature change of a boiler fluid at one location during no more than substantially one stroke of the sootblower; and operating the sootblower wherein at least one of a frequency of use or a steam output of the sootblower is selected based, at least in part, on the calculated temperature change.
 2. The method according to claim 1 wherein the boiler fluid is selected from a group of boiler fluids consisting of combustion gases, steam, and water.
 3. The method according to claim 1 further comprising measuring the temperature change of the boiler fluid at an output of a generating section, a superheater section, or an economizer section of a boiler.
 4. The method according to claim 1 wherein the calculating of the temperature change comprises calculating a first temperature change during the no more than substantially one stroke during a first sootblower sequence, and wherein the method further comprises: calculating a second temperature change of the boiler fluid during no more than substantially one stroke of the sootblower during a second sootblower sequence; and averaging the first and second temperature changes; wherein at least one of the frequency of operation or the steam output of the sootblower is selected based, at least in part, on the average of the first and second temperature changes.
 5. The method according to claim 1 further comprising normalizing the temperature change by at least one of an average boiler fluid temperature, a steam generation rate, a boiler fuel input rate, a combustion air input rate, or combinations thereof.
 6. The method according to claim 1 wherein the calculating comprises calculating the temperature change during a fraction of the sootblower stroke and wherein the fraction comprises a forward portion of the stroke or a reverse portion of the stroke.
 7. The method according to claim 1 further comprising operating a plurality of sootblowers in the boiler, wherein the frequency of use or the steam output of the plurality of sootblowers are selected, based at least in part, on the temperature change.
 8. The method according to claim 7, further comprising calculating a plurality of temperature changes of the boiler fluid, each temperature change occurring during no more than one stroke of a respective sootblower; and optimizing a frequency of use of each of the respective sootblowers based, at least in part, on the temperature changes.
 9. The method according to claim 1, wherein the temperature change is a first temperature change, the method further comprising: calculating a second temperature change of the boiler fluid at the one location during a time when no sootblowers upstream of the one location are stroking; calculating an effective temperature change based, at least in part, on the first and second temperature changes; and wherein the at least one of the frequency or steam output of the sootblower is selected, based at least in part, on the effective temperature change.
 10. A boiler comprising: a furnace configured to combust a fuel and generate combustion gases; a plurality of heat traps, each of the plurality of heat traps comprising tubes carrying a boiler fluid, the tubes having heat transfer surfaces and configured to transfer heat from the combustion gases to the boiler fluid carried by the tubes; a temperature sensor configured to measure a temperature of the combustion gases or the boiler fluid; a plurality of sootblowers, each of the plurality of sootblowers configured to remove deposits from a portion of the heat transfer surfaces in a vicinity of the respective sootblower; a sootblower controller coupled to the plurality of sootblowers and configured to operate the plurality of sootblowers in accordance with a sootblowing sequence, wherein each of the plurality of sootblowers is operated with a respective frequency and steam output, and wherein the respective frequency or steam output of each of the plurality of sootblowers is selected based, at least in part, on a temperature change measured by the temperature sensor during substantially one stroke or less of the respective sootblower.
 11. The boiler according to claim 10, wherein the boiler fluid is selected from a group of boiler fluids consisting of steam and water.
 12. The boiler according to claim 10, wherein the temperature sensor is positioned to measure a temperature of the combustion gases or the boiler fluid at an output of a generating section, a superheater section, or an economizer section of the boiler.
 13. The boiler according to claim 10, wherein the temperature sensor is positioned to measure a temperature of the combustion gases or the boiler fluid at a location within a generating section, a superheater section, or an economizer section of the boiler.
 14. The boiler according to claim 10, wherein the respective frequency or steam output of each of the plurality of sootblowers is selected based, at least in part, on a temperature change measured by the temperature sensor during a fraction of a stroke of the respective sootblower, and wherein the fraction comprises a forward portion of the stroke or a reverse portion of the stroke.
 15. The boiler according to claim 10, further comprising a data analyzer, the data analyzer coupled to the temperature sensor and the sootblower controller, wherein the data analyzer is configured to receive temperature measurements from the temperature sensor and sootblower control signals from the controller, wherein the sootblower control signals are indicative of a start or stop of a sootblower stroke for each of the plurality of sootblowers, and wherein the data analyzer is further configured to calculate the temperature change during substantially one stroke or less of each of the respective sootblowers, and couple control signals to the sootblower controller indicative of the selected frequency or steam output of each of the plurality of sootblowers.
 16. The boiler according to claim 15, wherein the data analyzer is further configured to calculate the selected frequency or steam output of each of the plurality of sootblowers based on the temperature changes.
 17. The boiler according to claim 15, wherein the temperature change comprises a first temperature change measured during a first sootblowing sequence, and wherein the data analyzer is further configured to calculate a second temperature change during substantially one stroke or less of each of the plurality of sootblowers during a second sootblowing sequence, and wherein the data analyzer is further configured to average the first and second temperature changes; wherein at least one of the frequency of operation or the steam output of each of the plurality of sootblowers is selected based, at least in part, on the average of the first and second temperature changes.
 18. The boiler according to claim 15, wherein the data analyzer is further configured to normalize the temperature change by at least one of an average boiler fluid temperature, a steam generation rate, a boiler fuel input rate, a combustion air input rate, or combinations thereof.
 19. The boiler according to claim 15, wherein the data analyzer is further configured to optimize a frequency of use of each of the respective sootblowers based, at least in part, on the temperature changes.
 20. The boiler according to claim 15, wherein the temperature change during substantially one stroke or less of the respective sootblower is a first temperature change, and wherein the data analyzer is further configured to calculate a second temperature change of the combustion gases or other boiler fluid during a time none of the sootblowers upstream of the temperature sensor are stroking, and combine the second temperature change with the respective first temperature changes to yield respective effective temperature changes for each sootblower, and wherein the frequency or steam output of each of the sootblowers is based, at least in part, on the respective effective temperature changes.
 21. A data analyzer comprising: a first input configured to receive temperature measurements of a boiler fluid from a temperature sensor within a boiler; a second input configured to receive a signal from a sootblower controller indicative of a first position in a sootblower stroke; and a processing unit coupled to the first and second inputs and configured to receive the temperature measurements and the signal from the sootblower controller, wherein the processing unit is configured to calculate a temperature change of the boiler fluid during substantially one stroke or less of the sootblower, wherein the calculation is based at least in part on a temperature measurement corresponding to the first position of the sootblower stroke; the processing unit further configured to select at least one of a frequency of use or steam output of the sootblower based, at least in part, on the temperature change, the processing unit further configured to provide the selected frequency or steam output to the sootblower controller.
 22. The data analyzer according to claim 21, wherein the boiler fluid is selected from a group of boiler fluids consisting of combustion gases, steam, and water.
 23. The data analyzer according to claim 21, wherein the temperature measurements are taken from an output of a generating section, a superheater section, or an economizer section of the boiler.
 24. The data analyzer according to claim 21, wherein the selected frequency or steam output of each of the sootblower is selected based, at least in part, on a temperature change measured by the temperature sensor during a fraction of a stroke of the sootblower, and wherein the fraction comprises a forward portion of the stroke or a reverse portion of the stroke.
 25. The data analyzer according to claim 21, wherein the data analyzer is further configured to normalize the temperature change by at least one of an average boiler fluid temperature, a steam generation rate, a boiler fuel input rate, a combustion air input rate, or combinations thereof.
 26. The data analyzer according to claim 21, wherein the temperature change is a first temperature change, and wherein the data analyzer is further configured to calculate a second temperature change of the boiler fluid at the location of the temperature sensor during a time when no sootblowers downstream of the location are stroking, the data analyzer further configured to combine the first and second temperature changes to yield an effective temperature change, and wherein the frequency of use or the steam output of the sootblower is based, at least in part, on the effective temperature change.
 27. The data analyzer according to claim 21, wherein the second input is further configured to receive a plurality of signals from the sootblower controller, each indicative of a position of a respective sootblower of a plurality of sootblowers, wherein the processing unit is further configured to calculate the temperature change during substantially one stroke or less of each of the respective sootblowers in the plurality of sootblowers, and provide control signals to the sootblower controller indicative of a selected frequency or steam output for each of the plurality of sootblowers.
 28. The data analyzer according to claim 27, wherein the processing unit is further configured to optimize a frequency of use of each of the respective sootblowers based, at least in part, on the temperature changes.
 29. The data analyzer according to claim 21, wherein the temperature change comprises a first temperature change measured during a first sootblowing sequence, and wherein the processing unit is further configured to calculate a second temperature change during substantially one stroke or less of the sootblower during a second sootblowing sequence, and wherein the processing unit is further configured to average the first and second temperature changes; wherein at least one of the frequency of operation or the steam output of the sootblower is selected based, at least in part, on the average of the first and second temperature changes.
 30. A system comprising: the data analyzer according to claim 21; and the temperature sensor configured to couple to the second input and further configured for placement in the boiler.
 31. A method for measuring carryover of ash or other fouling material from the boiler, the method comprising: receiving temperature measurements of a boiler fluid from a location within the boiler; receiving an indication of a time during which sootblowers upstream of the location are not in operation; and calculating a temperature change of the boiler fluid during the time the sootblowers upstream of the location are not in operation.
 32. The method according to claim 31, wherein the boiler fluid is selected from a group of boiler fluids consisting of combustion gas, steam, and water.
 33. The method according to claim 31, wherein the location is within a generating section, a superheater section, or an economizer section of the boiler.
 34. The method according to claim 31, wherein the location is at an output of a generating section, a superheater section, or an economizer section of the boiler. 